PROPOSED SETTLEMENT AGREEMENT

EX-10.17 8 a12-3670_4ex10d17.htm EX-10.17

Exhibit 10.17

 

ARIZONA PUBLIC SERVICE COMPANY

 

 

PROPOSED SETTLEMENT AGREEMENT

 

 

DOCKET NO. E-01345A-11-0224

 

 

January 6, 2012

 

1



 

TABLE OF CONTENTS

 

I.

RECITALS

5

 

 

 

II.

RATE CASE STABILITY PROVISION

6

 

 

 

III.

RATE INCREASE

6

 

 

 

IV.

BILL IMPACT

7

 

 

 

V.

COST OF CAPITAL

7

 

 

 

VI.

DEPRECIATION/AMORTIZATION AND DECOMMISSIONING

8

 

 

 

VII.

FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS

8

 

 

 

VIII.

RENEWABLE ENERGY

9

 

 

 

IX.

ENERGY EFFICIENCY/LOST FIXED COST RECOVERY/OPT-OUT RESIDENTIAL RATE/LARGE GENERAL SERVICE CUSTOMER EXCLUSION

10

 

 

 

X.

RATE TREATMENT RELATED TO ANY ACQUISITION BY APS OF SOUTHERN CALIFORNIA EDISON’S SHARE OF FOUR CORNERS UNITS 4-5

15

 

 

 

XI.

MODIFICATION TO ENVIRONMENTAL IMPROVEMENT SURCHARGE

16

 

 

 

XII.

COST DEFERRAL RELATED TO CHANGES IN ARIZONA PROPERTY TAX RATE

16

 

 

 

XIII.

TRANSMISSION COST ADJUSTMENT MECHANISM

17

 

 

 

XIV.

LOW INCOME PROGRAMS

18

 

 

 

XV.

SERVICE SCHEDULE 3 (LINE EXTENSIONS)

18

 

 

 

XVI.

BILL PRESENTATION

18

 

 

 

XVII.

RATE DESIGN

18

 

 

 

XVIII.

COMPLIANCE MATTERS

19

 

 

 

XIX.

FORCE MAJEURE PROVISION

20

 

2



 

XX.

COMMISSION EVALUATION OF PROPOSED SETTLEMENT

20

 

 

 

XXI.

MISCELLANEOUS PROVISIONS

21

 

3



 

PROPOSED SETTLEMENT AGREEMENT OF DOCKET NO.

E-01345-A-11-0224 ARIZONA PUBLIC SERVICE COMPANY REQUEST
FOR
RATE ADJUSTMENT

 

The purpose of this Settlement Agreement (“Agreement”) is to settle disputed issues related to Docket No. E-01345A-11-0224, Arizona Public Service Company’s (“APS” or “Company”) application to increase rates.  This Agreement is entered into by the following entities:

 

Arizona Corporation Commission Utilities Division (“Staff”)

Arizona Public Service Company (“APS”)

Residential Utility Consumer Office (“RUCO”)

Cynthia Zwick

Federal Executive Agencies (“FEA”)

Kroger Co. (“Kroger”)

Freeport-McMoRan Copper & Gold Inc. (“Freeport-McMoRan”)

Arizonans for Electric Choice and Competition (“AECC”)

Wal-Mart Stores, Inc. and Sam’s West, Inc. (“Wal-Mart”)

IBEW Locals 387, 640, 769 (“IBEW”)

AzAg Group (“AzAG”)

Arizona Competitive Power Alliance (“AzCPA”)

AARP (“AARP”)

Arizona Association of Realtors (“AAR”)

Barbara Wyllie-Pecora (“Wyllie-Pecora”)

Arizona Investment Council (“AIC”)

Southwestern Power Group II, LLC (“SWPG”)

Bowie Power Station, LLC (“Bowie”)

Noble Americas Energy Solutions LLC (“Noble”)

Constellation NewEnergy, Inc. (“Constellation”)

Direct Energy, LLC (“Direct”)

Shell Energy North America (US), L.P. (“Shell”)

 

These entities shall be referred to collectively as “Signatories;” a single entity shall be referred to individually as a “Signatory.”

 

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I.             RECITALS

 

1.1          APS filed the rate application underlying Docket No. E-01345A-11-0224 on June 1, 2011.  Staff found the application sufficient on July 1, 2011.

 

1.2          Subsequently, the Arizona Corporation Commission (“Commission”) approved applications to intervene filed by AARP, Arizona Association of Realtors, AzCPA, AIC, ASBA, Association of School Business Officials, AZAg Group, Barbara Wyllie-Pecora, Cynthia Zwick, FEA, Freeport-McMoRan and AECC (collectively “AECC”), IBEW Locals 387, 640 and 769, Interwest, Kroger, Mel Beard, Noble et al, NRDC, RUCO, SWEEP, SWPG, Bowie, TEP, the Town of Gilbert, the Town of Wickenburg, Wal-Mart and Sam’s Club,   and WRA.  Mel Beard subsequently withdrew as an intervenor in the case.

 

1.3          APS filed a notice of settlement discussions on November 18, 2011.  Settlement discussions began on November 30, 2011.  The settlement discussions were open, transparent, and inclusive of all parties to this Docket who desired to participate.  All parties to this Docket were notified of the settlement discussion process, were encouraged to participate in the negotiations, and were provided with an equal opportunity to participate.  Commission Staff filed a Preliminary Term Sheet regarding this matter on December 9, 2011, which was discussed in a Special Open Meeting held on December 16, 2011.

 

1.4          The terms of this Agreement are just, reasonable, fair, and in the public interest in that they, among other things, establish just and reasonable rates for APS customers; promote the convenience, comfort and safety, and the preservation of health, of the employees and patrons of APS; resolve the issues arising from this Docket; and avoid unnecessary litigation expense and delay.

 

1.5          The Signatories believe that this Agreement balances the interests of both APS and its customers.  These benefits include:

 

·        an overall zero dollar base rate increase;

 

·        a zero percent bill impact for the remainder of 2012 (Commission-approved adjustors (including the possibility of a Four Corners rider pursuant to paragraph 10.3) may increase customer bills after December 31, 2012);

 

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·        a four year rate case stay out, in which APS agrees not to raise base rates as a result of any new general rate case filing prior to July 1, 2016;

 

·        a buy-through rate for industrial and large commercial customers;

 

·        a narrowly-tailored Lost Fixed Cost Recovery (“LFCR”) mechanism that supports energy efficiency (“EE”) and distributed generation (“DG”) at any level or pace set by this Commission;

 

·        an opt-out rate design for residential customers who choose not to participate in the LFCR;

 

·        a process for simplifying customers’ bill format; and

 

·        bill assistance for additional low income customers, at shareholder expense.

 

1.6          The Signatories agree to ask the Commission (1) to find that the terms and conditions of this Agreement are just and reasonable and in the public interest, along with any and all other necessary findings, and (2) to approve the Agreement and order that it and the rates contained herein become effective on July 1, 2012.

 

TERMS AND CONDITIONS

 

II.            RATE CASE STABILITY PROVISION

 

2.1          APS agrees not to file its next general rate case prior to May 31, 2015.  The test year end date for the base rate increase filing contemplated in this section shall be no earlier than December 31, 2014 but need not coincide with the end of a calendar year.  No new base rates resulting from APS’s next general rate case will be effective before July 1, 2016.

 

III.          RATE INCREASE

 

3.1          APS shall receive a base rate increase of zero dollars (“revenue requirement”).  This amount is comprised of: (1) a non-fuel base rate increase of $116.3 million, which includes providing for a return on and of plant that is in service as of March 31, 2012 (“Post-Test Year Plant”); (2) a fuel base rate decrease of

 

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$153.1 million; and (3) a transfer of cost recovery from the Renewable Energy Surcharge (“RES”) to base rates described in Paragraph VIII herein.

 

3.2          The Company’s jurisdictional fair value rate base used to establish the rates agreed to herein is $8,167,126,000. The Company’s total adjusted Test Year revenue is $2,868,858,000.

 

IV.          BILL IMPACT

 

4.1          When new rates become effective, customers will have on average a 0.0% bill impact or less.  This zero percent or slightly negative bill impact will be achieved by allowing the negative credit that exists in the Company’s Power Supply Adjustor (“PSA”) to continue until February 1, 2013, at which time it will reset.  The annual 4 mill cap will be applied after the impact of the expiration of the then-current PSA credit.

 

4.2          Subsequent to the PSA reset for General Service customers in February 2013, the percentage bill impact spread resulting from this Settlement among the various segments of that customer class shall be equal.  This shall be accomplished as set forth in Attachment A.

 

4.3          A zero percent bill impact will continue for the remainder of 2012 (Commission-approved adjustors (including the possibility of a Four Corners rider pursuant to paragraph 10.3) may increase customer bills after December 31, 2012).

 

V.            COST OF CAPITAL

 

5.1          A capital structure comprised of 46.06% debt and 53.94% common equity shall be adopted.

 

5.2          A return on common equity of 10.0% and an embedded cost of debt of 6.38% shall be adopted.

 

5.3          A fair value rate of return of 6.09%, which includes a return on the fair value rate base increment of 1.0%, shall be adopted.

 

5.4          The provisions set forth herein regarding the quantification of cost of capital, fair value rate base, fair value rate of return, and the revenue requirement are made for purposes of settlement only and should not be construed as admissions against interest or waivers of litigation positions related to other or future cases.

 

7



 

VI.          DEPRECIATION/AMORTIZATION AND DECOMMISSIONING

 

6.1          With the exception of Uniform System of Accounts 370.01 (electronic meters), 370.02 (electro-mechanical meters), and 370.03 (AMI meters), the depreciation and amortization rates proposed by APS and contained in Attachment REW-2 to Dr. Ron White’s Pre-filed Direct Testimony shall be adopted until further order of the Commission.  For Accounts 370.01, 370.02 and 370.03, the current depreciation rates will be retained, as proposed by Commission Staff Witness Ralph Smith.

 

6.2          The annual nuclear decommissioning amounts reflected in the rates agreed to herein are those shown in APS Witness Jason LaBenz workpaper JCL_WP22, page 4, attached hereto as Attachment B.

 

6.3          APS shall file a request that the Commission adjust the Company’s System Benefit Charge (“SBC”) and reduce such charge to reflect a corresponding reduction of the decommissioning trust funding obligations collected through the SBC related to the full funding of Palo Verde Unit 2.  Such filing shall be made in sufficient time for the reduction to occur by January 2016.

 

VII.         FUEL AND POWER SUPPLY ADJUSTMENT PROVISIONS

 

7.1          The base fuel rate shall be lowered from $0.037571 per kWh as set in Commission Decision No. 71448 to $0.032071 per kWh.  This change shall take effect on the effective date of the new rates contained in this Agreement, in accordance with the current approved Plan of Administration for the Power Supply Adjustor (“PSA”).

 

7.2          For purposes of this case, APS will withdraw its request to recover through the PSA the cost of chemicals required for environmental compliance at APS’s power plants, and APS shall not raise this request before its next general rate case.

 

7.3          The 90/10 sharing provision in APS’s PSA will be eliminated.  The PSA shall be modified to require APS to apply interest on the PSA balance annually, rather than monthly, at the following rates:  any over-collection existing at the end of the PSA year will accrue interest at a rate equal to the Company’s authorized ROE or APS’s then-existing short term borrowing rate, whichever is greater, and will be refunded to customers over the following 12 months; any under-collection existing at the end of the PSA year will accrue interest at a rate

 

8



 

equal to the Company’s authorized ROE or APS’s then-existing short term borrowing rate, whichever is less, and will be recovered from customers over the following 12 months.  APS may, at any time during the PSA year, request to reduce the PSA rate through the Transition Component.  Any such request shall become effective beginning with the first billing cycle of the month following the filing date of the request.

 

7.4          To incent prudent fuel and power procurement and use, APS shall be subject to periodic audits.  The first audit shall be for calendar year 2014.  Commission Staff shall select a consultant to perform this audit and subsequent audits.  Each audit shall be funded by APS in an amount not to exceed $100,000 per audit.

 

7.5          The PSA Plan of Administration shall be amended as set forth in Attachment C.

 

VIII.       RENEWABLE ENERGY

 

8.1          APS currently collects the costs associated with certain APS-owned renewable energy projects through the RES.  Consistent with the treatment of other Post-Test Year Plant adopted in this Agreement, the portion of those renewable projects that have been closed to plant in service as of March 31, 2012, shall be rate based and recovery of those costs shall be accomplished through base rates.  The specific projects to be rate based pursuant to this Section are identified in Attachment D.

 

8.2          Effective with the date of the Commission’s order in this matter, the capital carrying costs(1) for any APS renewable energy-related capital investments shall not be recovered through the RES adjustor, except that capital carrying costs for renewable energy-related capital investments that APS makes in compliance with Commission Decision No. 71448 shall be recovered in the RES adjustor unless and until specifically authorized for recovery in another adjustor or in base rates.

 

8.3          On the effective date of the new rates contained in this Agreement, the RES adjustor rate established for 2012 in Docket No. E-01345A-11-0264 shall be reduced to reflect the removal of the projects identified in Attachment D.  At the same time, the renewable energy-related purchased power agreement costs that were moved from the RES to the PSA pursuant to the Commission’s

 


(1)

Capital carrying costs include (1) a return at the Company’s Weighted Average Cost of Capital approved by the Commission in this rate case; (2) depreciation expense; (3) income taxes; (4) property taxes; (5) deferred taxes and tax credits where appropriate; and (6) associated O&M.

 

9



 

Decision in Docket No. E-01345A-11-0264, shall be transferred back to the RES.

 

8.4          To provide the Commission with greater flexibility in setting RES adjustor rates and related caps, the requirement established in Decision No. 67744 that any changes to RES charges and caps must be allocated between customer classes according to certain set proportions shall be eliminated.

 

IX.          ENERGY EFFICIENCY/LOST FIXED COST RECOVERY/OPT-OUT RESIDENTIAL RATE/LARGE GENERAL SERVICE CUSTOMER EXCLUSION

 

9.1          The Signatories support energy efficiency as a low cost energy resource.  The Signatories also recognize that, under APS’s current volumetric rate design, the Company recovers a significant portion of its fixed costs of service through kilowatt-hour (“kWh”) sales.  Commission rules related to EE and Distributed Generation (“DG”) require APS to sell fewer kWh, which, in turn, prevents the Company from being able to recover a portion of the fixed costs of service embedded in its energy rates.

 

9.2          The Signatories also recognize the Commission’s interest in directing EE and DG policy.  In signing this Agreement, the Signatories intend that a Lost Fixed Cost Recovery (“LFCR”) mechanism with residential opt-out rates shall be adopted that allows APS relief from the financial impact of verified lost kWh sales attributable to Commission requirements regarding EE and DG while preserving maximum flexibility for the Commission to adjust EE and DG requirements, either upward or downward, as the Commission may deem appropriate as a matter of policy.  Nothing in this Agreement is intended to bind the Commission to any specific EE or DG policy or standard.

 

9.3          To address the goals of Sections 9.1 and 9.2, the Signatories propose that the Commission adopt for APS an LFCR, similar to that recommended by Staff in this proceeding.  The LFCR shall recover a portion of distribution and transmission costs associated with residential, commercial and industrial customers when sales levels are reduced by EE and DG. It shall not recover lost fixed costs attributable to other potential factors, such as weather or general economic conditions.  The LFCR mechanism shall exclude the portion of distribution and transmission costs that is recovered through the Basic Service Charge (“BSC”) and fifty (50) percent of such costs recovered through non-generation/non-TCA demand charges.

 

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9.4          The LFCR shall be adjusted annually to account for the unrecovered costs associated with a portion of distribution and transmission costs resulting from EE programs as demonstrated by the Measurement, Evaluation and Reporting (“MER”) conducted for EE programs and from DG as demonstrated pursuant to the means described in Section 9.5 below.  An annual 1% year over year cap based on Total Company revenues will be applied to the adjustment.  Any amount in excess of the 1% cap will be deferred (with interest at the nominal one-year Treasury Constant Maturities rate contained in the Federal Reserve Statistical Release H-15 or its successor publication) for collection until the first future adjustment period in which including such costs, would not cause the annual increase to exceed the 1% cap.  The amount of any cap level set herein shall be evaluated in APS’s next rate case.

 

9.5          For the purpose of the LFCR mechanism, APS shall be allowed to use statistical verification, output profile, or meter data for DG systems until December 31, 2014.  Beginning January of 2015, APS shall only use meter data to calculate DG system savings

 

9.6          APS will file with the Commission to adjust its LFCR by January 15 of each year, and Staff will use its best efforts to process the matter by March 1 of each year.  Each annual LFCR adjustment will not go into effect unless approved by the Commission. The annual adjustment will use actual data for the period through September and forecast data for the remainder of the year. The following year’s adjustment shall be trued-up for verified EE MER and metered or otherwise verified DG results.  The first adjustment will not occur before March 1, 2013.  The March 1, 2013 adjustment shall include reduced sales from EE and DG for 2012 and will be pro-rated from the date rates become effective pursuant to a Commission decision on this Agreement. Subsequent adjustments shall reflect the full impact of reduced sales in the prior year plus the cumulative impact from previous adjustments, subject to the cap described in Section 9.4 herein.

 

9.7          The LFCR mechanism shall not apply to large General Service customers taking service under rate schedules E-32 L, E-32 L TOU, E-34, E-35 and E-36 XL, or to unmetered General Service customers under E-30 and lighting schedules. These rate schedules shall be modified in accordance with Attachment K to address unrecovered fixed costs through changes in rate design with enhanced distribution demand and BSC charges and a corresponding adjustment to energy charges.

 

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9.8           Residential customers shall have a rate schedule choice to opt out of the LFCR by electing an optional BSC, graduated by kWh monthly usage.  That option is attached hereto as Attachment E.  The optional BSC will be incorporated into each residential rate schedule to provide customers with the maximum flexibility to opt out without requiring a shift to a different rate schedule. The purpose of this opt out rate is to replicate, on average, the effects of the LFCR.

 

9.9           APS shall seek stakeholder input regarding the development of a customer outreach program to inform and educate customers about both the LFCR and voluntary opt-out rates and shall implement this outreach program.

 

9.10         On January 15 of each year, APS shall file compliance reports with the Commission consistent with the schedules attached to the LFCR Plan of Administration. These reports shall include a comparison of the revenues recovered through the LFCR to those that would have been recovered had the Company’s revenue per customer decoupling (full decoupling) proposal been adopted.

 

9.11         The LFCR shall be subject to Commission review at any time, the first to occur no later than APS’s next general rate case.  If the Commission decides to suspend, terminate, or materially modify the LFCR mechanism prior to the Company’s next general rate case, and does not provide alternative relief that adequately addresses fixed cost revenue erosion, the moratorium for filing general rate case applications shall terminate.

 

9.12         The LFCR Plan of Administration is attached hereto as Attachment F.

 

9.13         The LFCR was designed to be a flexible means to maximize the policy options available to the Commissioners and to customers, allowing the pursuit of EE and DG programs at any level or pace directed by the Commission.  The Signatories agree that if the Commission declines to adopt the LFCR or an alternative mechanism that adequately addresses fixed cost revenue erosion in this case, APS shall be granted relief from either the relevant EE and DG requirements or the financial impacts of EE and DG during that time.

 

9.14         For future Demand-Side Management (“DSM”) Implementation Plan filings:

 

(a)   Beginning with APS’s 2013 DSM Implementation Plan (filed in 2012), and excluding DSM-related capital investments already authorized by the

 

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Commission, carrying costs for DSM-related capital investments shall not be recovered through the DSM Adjustment Clause.

 

(b)   APS’s performance incentive shall be modified (1) to eliminate the top two tiers of percentages to be applied to Net Benefits or Percent of Program Costs based on APS’s achievement relative to the EE Standard, and (2) to change the fourth tier to include any achievement greater than 105%.  The first three tiers remain unchanged.

 

Achievement Relative to
the Energy Efficiency 
Standard

 

Performance
Incentive as % of
Energy Efficiency
Net Benefits

 

Performance
Incentive Capped
at % of Energy
Efficiency 
Program Costs

 

Proposed 
Change from 
Current

 

 

 

 

 

 

 

 

 

<85%

 

0

%

0

%

No Change

 

 

 

 

 

 

 

 

 

85% to 95%

 

6

%

12

%

No Change

 

 

 

 

 

 

 

 

 

96% to 105%

 

7

%

14

%

No Change

 

 

 

 

 

 

 

 

 

>105%

 

8

%

16

%

New

 

 

 

 

 

 

 

 

 

106% to 115%

 

8

%

16

%

Eliminated

 

 

 

 

 

 

 

 

 

116% to 125%

 

9

%

18

%

Eliminated

 

 

 

 

 

 

 

 

 

>125%

 

10

%

20

%

Eliminated

 

 

(c)   APS shall use the inputs and methodology that Commission Staff uses when calculating the present value of benefits and costs for DSM measures in its Societal Cost test.  Commission Staff will regularly re-evaluate such inputs

 

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and methodologies, considering comments from APS and other stakeholders.

 

(d)   APS will work with stakeholders and Staff to develop and file for Commission consideration a new performance incentive structure by December 31, 2012 that optimizes the connection between energy efficiency, rates and utility business incentives and that creates a clear connection between the level of performance incentive and achievement of cost-effective energy savings.  This rate case shall be held open to allow for Commission approval of including the new performance incentive structure in the DSM Adjustment Clause.  At that time, the Commission should determine the plan year to which the new performance incentive structure shall apply.  The Signatories shall recommend that any new performance incentive structure adopted should apply to the first plan year filed after its adoption.

 

(e)   APS’s DSM programs and associated energy savings shall be independently reviewed every five years by an evaluator selected by Staff and paid for by APS in an amount not to exceed $100,000.  The first review shall occur in APS’s next general rate case or within five (5) years of a Commission order in this case, whichever is sooner.

 

9.15         APS shall compile and make available to all parties of the docket a technical reference manual documenting program and measure saving assumptions and incremental costs no later than December 31, 2013.  This manual would be updated on an annual basis as part of the DSM implementation plan process and would serve as a reference tool for the LFCR analysis.

 

9.16         APS currently collects $10 million of DSM costs in base rates, which level will be retained.

 

9.17         The DSM Adjustment Clause Plan of Administration shall be modified to reflect the terms of this Agreement as set forth in Attachment G.

 

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X.            RATE TREATMENT RELATED TO ANY ACQUISITION BY APS OF SOUTHERN CALIFORNIA EDISON’S SHARE OF FOUR CORNERS UNITS 4-5.

 

10.1         In Docket No. E-01345A-10-0474, APS has sought Commission permission to pursue acquisition of Southern California Edison’s (“SCE”) current ownership interest in Four Corners Units 4 and 5 and to retire Four Corners Units 1-3 (the “proposed Four Corners transaction”).

 

10.2        Except as provided in Section 9.14(d), this rate case shall remain open for the sole purpose of allowing APS to file a request, no later than December 31, 2013, that its rates be adjusted to reflect the proposed Four Corners transaction, should the Commission allow APS to pursue the acquisition and should the transaction thereafter close. Specifically, APS may within ten (10) business days after any Closing Date but no later than December 31, 2013, file an application with the Commission seeking to reflect in rates the rate base and expense effects associated with the acquisition of SCE’s share of Units 4 and 5, the rate base and expense effects associated with the retirement of Units 1-3, and any cost deferral authorized in Docket No. E-01345A-10-0474.  APS shall also be permitted to seek authorization to amend the PSA Plan of Administration to include in the PSA the post-acquisition Operations and Maintenance expense associated with Four Corners Units 1-3 as a cost of producing off-system sales until closure of Units 1-3, provided that such costs do not exceed off-system sales revenue in any given year.  APS’s rates shall be adjusted only if the Commission finds the Four Corners transaction to be prudent.

 

10.3         Any filing seeking a rate adjustment pursuant to Section 10.2 shall include at a minimum the following schedules: (1) the most current APS balance sheet at the time of filing; (2) the most current APS income statement at the time of filing; (3) an earnings schedule that demonstrates that the operating income resulting from the rate adjustment does not result in a return on rate base in excess of that authorized by this Agreement in the period after the rate adjustment becomes effective; (4) a revenue requirement calculation, including the amortization of any deferred costs; (5) an adjustment rider that recovers the rate base and non-PSA related expenses associated with any Four Corners acquisition on an equal percentage basis across all rate schedules which shall not become effective before July 1, 2013; (6) an adjusted rate base schedule; and (7) a typical bill analysis under present and filed rates.

 

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10.4         The Signatories shall not raise any issues in the rate adjustment proceeding other than those specifically described in Section 10.2.  The Signatories shall use good faith efforts to process this rate adjustment request within a reasonable time.

 

10.5         If, at any time, APS determines that the Four Corners Transaction will not close, it shall so inform the Commission and the Signatories by filing a Notice to that effect in this Docket.

 

XI.           MODIFICATION TO ENVIRONMENTAL IMPROVEMENT SURCHARGE

 

11.1         For purposes of this proceeding, APS shall withdraw its request for approval of the proposed Environmental and Reliability Account (“ERA”) mechanism, and APS shall not raise this request before its next general rate case.

 

11.2         APS shall implement a revised version of the existing Environmental Improvement Surcharge (“EIS”).  As amended, APS shall no longer receive customer dollars through the EIS to pay for government-mandated environmental controls.  However, when APS invests capital to fund any government-mandated environmental controls, the EIS will recover the associated capital carrying costs, subject to a cap equal to the charge currently in place for the EIS.  Adjustments to the EIS shall become effective each April 1st unless Staff requests Commission review or unless otherwise ordered by the Commission.  APS will not request a change in the rate cap prior to its next general rate case.

 

11.3         APS will be held responsible for demonstrating that the environmental controls were government-mandated and represented a reasonable and prudent option available to the Company at that time sufficient to meet the environmental requirements.

 

11.4         The EIS Plan of Administration shall be revised as set forth in Attachment H.

 

11.5         The existing EIS will be reset to zero on the effective date of the new rates contained in this Agreement.

 

XII.         COST DEFERRAL RELATED TO CHANGES IN ARIZONA PROPERTY TAX RATE

 

12.1         APS shall be allowed to defer for future recovery, in accordance with the provisions of Accounting Standards Codification (“ASC”) 980 (formerly SFAS

 

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No. 71), the following portions of Arizona property tax expense above or below the test year level of $141.5 million caused by changes to the applicable Arizona composite property tax rate (not changes in the assessed value of property).

 

(a)   When the property tax rate increases:

 

·      For 2012: 25% (prorated with an assumed July 1 rate effective date);

·      For 2013: 50%; and

·      For 2014 and all subsequent years: 75%.

 

(b)   When the property tax rate decreases: 100% in all years.

 

No interest shall be applied to the deferred balance.

 

12.2         Beginning with the effective date of the Commission decision resulting from APS’s next general rate case, any final property tax rate deferral that has a positive balance will be recovered from customers over 10 years and any deferral that has a negative balance will be refunded to customers over 3 years.

 

12.3         The Signatories reserve the right to review APS’s property tax deferrals for reasonableness and prudence such that the deferrals can be recognized in accordance with the provisions of ASC-980 (formerly SFAS No. 71).

 

XIII.       TRANSMISSION COST ADJUSTMENT MECHANISM

 

13.1         The level of transmission costs presently in APS’s base rates will remain in base rates until further order of the Commission.

 

13.2         The annual TCA adjustment will become effective June 1 of each year without the need for affirmative Commission approval, unless Staff requests Commission review or unless otherwise ordered by the Commission.

 

13.3         APS shall file a notice with Docket Control that includes its revised TCA tariff, along with a copy of its FERC information filing of its annual update of transmission service rates pursuant to its Open Access Transmission tariff (“OATT”).  This notice shall be filed with the Commission by May 15 of each year.

 

13.4         The TCA Plan of Administration shall be modified as set forth in Attachment I.

 

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XIV.       LOW INCOME PROGRAMS

 

14.1         In Section 16.3 of the 2009 Settlement, APS committed to augment the bill assistance program approved in Decision No. 69663 by funding $5 million to assist customers whose incomes exceed 150% of the Federal Poverty Income Guidelines but are less than or equal to 200% of the Federal Poverty Income Guidelines.  This Agreement provides that any funds remaining of that $5 million funding requirement may be used to so assist customers whose incomes are less than or equal to 200% of the Federal Poverty Income Guidelines.

 

14.2         PSA and DSMAC adjustor rates shall apply to low-income customers.  The billing method for low income customers shall be simplified by transferring customers to their corresponding non-low income rate schedule and applying the PSA and DSMAC rate schedules to those bills, but then applying a discount to the total bill such that low income customers, like other APS customers, will have no bill impact in this case as a result of the billing method change.

 

XV.        SERVICE SCHEDULE 3 (LINE EXTENSIONS)

 

15.1         Version 12 of Service Schedule 3, as approved in Decision No. 72684 (November 18, 2011), shall become effective on the date that rates from this case become effective.

 

XVI.       BILL PRESENTATION

 

16.1         Within 90 days following approval of this Agreement, APS will initiate stakeholder meetings to address issues related to the APS bill presentation with a goal of making the bill easier for customers to understand.  APS shall thereafter file an application with the Commission for any authorization needed to modify its bill presentation. Such application shall explain how the APS bill presentation proposal reflects the input of stakeholders during the stakeholder meeting process.

 

XVII.      RATE DESIGN

 

17.1         The Company’s proposed Experimental Rate Schedule AG-1, a buy through rate for large commercial and industrial customers, should be capped at 200 MW and should be approved as modified herein, as should corresponding changes to the PSA.  Proposed Experimental Rate Schedule AG-1 is set forth in Attachment J.  Proposed Experimental Rate Schedule AG-1 does not address the subject of retail electric competition.

 

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17.2         APS shall make commercially reasonable efforts to eliminate or mitigate all unrecovered costs resulting from the AG-1 experimental program established in this docket.  If there are any lost fixed generation costs related to the AG-1 experimental rate, in its next general rate case, APS shall provide testimony that explains why it was unable to eliminate all lost fixed generation costs.  Because AG-1 is an experimental program that may benefit certain General Service customers, and because residential customers cannot participate in the program, any APS proposal in APS’s next general rate case that seeks to collect lost fixed generation costs related to the AG-1 experimental rate shall not propose to recover such costs from residential customers.

 

17.3         As recommended by Staff Witness McGarry, APS shall file a study in its next General Rate Case Application to support the cost basis of the various charges in Service Schedule 1,  taking into account the impact Smart Grid technology may have on these costs.

 

17.4         APS shall withdraw its request to establish Service Schedule 9, an economic development service schedule.  In its place, APS is authorized to pursue economic development opportunities through the use of Commission-approved special contracts.

 

17.5         The remaining rate design issues presented by this case shall be resolved as set forth in Attachment K.

 

XVIII.    COMPLIANCE MATTERS

 

18.1         Within ten days after the Commission issues a written order in this matter, APS shall file compliance schedules associated with this Docket for Staff review. Subject to Staff review, such compliance schedules will become effective on the effective date of the new rates contained in this Agreement.

 

18.2         APS shall report to the Commission identifying the extent of the challenges regarding workforce planning, the specific actions that APS is taking to address the issue, and the progress APS is making toward meeting those goals.  The workforce planning report, which shall be filed on an annual basis in this docket on or before May 31, shall be limited to the following job classifications:  Electrician-Journeyman, Lineman-Journeyman, Technician-E&I, and Operator-Power Plant (a/k/a Auxiliary Operators and Control Operators).  At a minimum, the workforce planning report shall set forth:  (1) the number of employees then currently holding these positions; (2) the present mean and median ages of APS’s workforce with respect to those job

 

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classifications; (3) the share of retirement-eligible employees, both as a percentage and in absolute terms, in each of these job classifications; and (4) anticipated hiring and attrition levels for each of these job classifications.

 

18.3         Decision No. 70667, as a compliance item, requires APS to periodically file with the Commission certain communications with rating agencies.  It is appropriate to eliminate this filing requirement at this time.

 

XIX.       FORCE MAJEURE PROVISION

 

19.1         Nothing in this Agreement shall prevent APS from requesting a change to its base rates in the event of conditions or circumstances that constitute an emergency.  For the purposes of this Agreement, the term “emergency” is limited to an extraordinary event that, in the Commission’s judgment, requires base rate relief in order to protect the public interest.  This provision is not intended to preclude APS from seeking rate relief or any Signatory from petitioning the Commission to examine the reasonableness of APS’s rates pursuant to this Section in the event of significant developments that materially impact the financial results expected under the terms of this Agreement.  This provision is not intended to preclude any party, including any Signatory to this Agreement, from opposing an application for rate relief filed by APS pursuant to this paragraph.  Nothing in this provision is intended to limit the Commission’s ability to change rates at any time pursuant to its lawful authority.

 

XX.        COMMISSION EVALUATION OF PROPOSED SETTLEMENT

 

20.1         All currently filed testimony and exhibits shall be offered into the Commission’s record as evidence.

 

20.2         The Signatories recognize that Staff does not have the power to bind the Commission.  For purposes of proposing a settlement agreement, Staff acts in the same manner as any party to a Commission proceeding.

 

20.3         This Agreement shall serve as a procedural device by which the Signatories will submit their proposed settlement of APS’s pending rate case, Docket No. E-01345A-11-0224, to the Commission.

 

20.4         The Signatories recognize that the Commission will independently consider and evaluate the terms of this Agreement.  If the Commission issues an order adopting all material terms of this Agreement, such action shall constitute

 

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Commission approval of the Agreement.  Thereafter, the Signatories shall abide by the terms as approved by the Commission.

 

20.5         If the Commission fails to issue an order adopting all material terms of this Agreement, any or all of the Signatories may withdraw from this Agreement, and such Signatory or Signatories may pursue without prejudice their respective remedies at law.  For purposes of this Agreement, whether a term is material shall be left to the discretion of the Signatory choosing to withdraw from the Agreement.  If a Signatory withdraws from the Agreement pursuant to this paragraph and files an application for rehearing, the other Signatories, except for Staff, shall support the application for rehearing by filing a document with the Commission that supports approval of the Agreement in its entirety. Staff shall not be obligated to file any document or take any position regarding the withdrawing Signatory’s application for rehearing.

 

XXI.       MISCELLANEOUS PROVISIONS

 

21.1         This case has attracted a large number of participants with widely diverse interests. To achieve consensus for settlement, many participants are accepting positions that, in any other circumstances, they would be unwilling to accept.  They are doing so because this Agreement, as a whole, is consistent with their long-term interests and with the broad public interest. The acceptance by any Signatory of a specific element of this Agreement shall not be considered as precedent for acceptance of that element in any other context.

 

21.2         No Signatory is bound by any position asserted in negotiations, except as expressly stated in this Agreement. No Signatory shall offer evidence of conduct or statements made in the course of negotiating this Agreement before this Commission, any other regulatory agency, or any court.

 

21.3         Neither this Agreement nor any of the positions taken in this Agreement by any of the Signatories may be referred to, cited, or relied upon as precedent in any proceeding before the Commission, any other regulatory agency, or any court for any purpose except to secure approval of this Agreement and enforce its terms.

 

21.4         To the extent any provision of this Agreement is inconsistent with any existing Commission order, rule, or regulation, this Agreement shall control.

 

21.5         Each of the terms of this Agreement is in consideration of all other terms of this Agreement. Accordingly, the terms are not severable.

 

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21.6         The Signatories shall make reasonable and good faith efforts necessary to obtain a Commission order approving this Agreement. The Signatories shall support and defend this Agreement before the Commission. Subject to paragraph 20.5, if the Commission adopts an order approving all material terms of the Agreement, the Signatories will support and defend the Commission’s order before any court or regulatory agency in which it may be at issue.

 

21.7         This Agreement may be executed in any number of counterparts and by each Signatory on separate counterparts, each of which when so executed and delivered shall be deemed an original and all of which taken together shall constitute one and the same instrument.  This Agreement may also be executed electronically or by facsimile.

 

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Docket No. E-0134SA-ll-0224 ARIZONA CORPORATION COMMISSION By ARIZONA PUBLIC SERVICE COMPANY RESIDENTIAL UTILITY CONSUMER OFFICE By By

 


Docket No. E-01345A-II-0224 DATED: January 5, 2012 By Cynthra Zwick

 


Docket No. E-01345A-ll-0224 By Karen S. White Karen S. White Federal Executive Agencies DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 Kurt J. Boehm, Esq. Attorney for Kroger Co. DATED: 1-6-12, 2012

 


Docket No. E-01345A-11-0224 By C. Webb Crockett C. Webb Crockett Patrick J. Black Fennemore Craig, P. C. Attorneys for Freeport-McMoRan Copper & Gold Inc. DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 By C. Webb Crockett Patrick J. Black Fennemore Craig, P.C. Attorneys for Arizonans for Electric Choice and Competition DATED: January 6, 2012

 


WAL-MART STORES, INC. and SAM'S WEST, INC. By: Scott S. Wakefield Ridenour, Hienton & Lewis, PLLC 201 N. Central Ave., Suite 3300 Phoenix, AZ 85004 Attorneys for Wal-Mart Stores, Inc. and Sam's West, Inc. Dated: January 6, 2012

 


.By: Nicholas J. Enoch, Esq. Docket No. E-0134SA-ll-0224 Attorney for Intervenors IBEW Locals 387, 640 & 769 DATED: January .6, 2012.

 


Docket No. E-01345A-11-0224 AZAG GROUP By: Jay I. Moyes Moyes Sellers & Hendricks 1850 N. Central Ave., Suite 1100 Phoenix, AZ 85004 [email protected] 602-604-2106 602-274-9135 - fax DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 By Greg Patterson Arizona Competitive Power Alliance Director: DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 DATED: 1/6, 2012 By Craig A. Martes Craig A. Martes AARP

 


Docket No. E-01345A-11-0224 ARIZONA ASSOCIATION OF REALTORS, INC. By: Tom Farley, Chief Executive Officer DATED: January 6, 2012

 


Docket No. E-01345A-l1-0224 By Barbara wyllie Pecora Barbara wyllie - Pecora DATED: 1-6-12, 2012

 


Docket No. E-01345A-11-0224 By Gary Yaquinto Gary Yaquinto, its President Arizona Investment Council DATED: January 5, 2012

 


Docket No. E-01345A-11-0224 Lawrence V. Robertson, Jr. On behalf of Southwestern Power Group II, L.L.C. DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 Lawrence V. Robertson, Jr. On behalf of Bowie Power Station, L.L.C. DATED: January 6, 2012 By

 


Docket No. E-01345A-ll-0224 Lawrence V. Robertson, Jr. On behalf of Noble Americas Energy Solutions LLC DATED: January 6, 2012 By

 


Docket No. E-01345A-l1-0224 By Lawrence V. Robertson, Jr. On behalf of Constellation NewEnergy, Inc. DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 By Lawrence V. Robertson, Lawrence V. Robertson, Jr. On behalf of Direct Energy, LLC DATED: January 6, 2012

 


Docket No. E-01345A-11-0224 Lawrence V. Robertson, Jr. On behalf of Shell Energy North America (US), L.P. DATED: January 6, 2012 By

 


153,087,000 27,689,606,547 0.00553 Adjusted kWh 1. 2. E-20 36,664,060 E-32 XS 1,418,941,092 E-32 S 2,551,982,755 E-32 M 3,279,541,910 E-32 L 3,647,138,613 E-32 TOU XS 4,608,869 E-32 TOU S 41,567,188 E-32 TOU M 69,936,556 E-32 TOU L 295,613,941 E-34 1,086,047,211 E-35 1,673,368,627 14,105,410,822 Arizona Public Service Company Equalize Impact of Transferring Fuel from Base Rates to PSA Across General Service Rate Classes Fuel transfer to PSA Test Year Retail kWh PSA impact /kWh Adjusted Equal % Equal % Present PSA PSA PSA PSA PSA Revenue Impact Impact Impact Impact Delta ($) ($) (%) (%) ($) ($) 3. 4. 5. 6. 7. 8. $ 3,885,908 $ 202,752 5.218% 5.82% $ 226,004 $ 23,252 199,176,817 7,846,744 3.940% 5.82% 11,584,124 3,737,380 290,020,650 14,112,465 4.866% 5.82% 16,867,601 2,755,136 317,315,278 18,135,867 5.715% 5.82% 18,454,236 318,369 303,798,301 20,168,677 6.639% 5.82% 17,668,909 (2,499,768) 632,665 25,487 4.029% 5.82% 36,796 11,309 4,454,447 229,867 5.160% 5.82% 259,071 29,204 6,385,132 386,749 6.057% 5.82% 371,359 (15,390) 22,916,517 1,634,745 7.133% 5.82% 1,332,825 (301,920) 80,597,093 6,005,841 7.452% 5.82% 4,687,527 (1,318,314) 112,009,467 9,253,729 8.262% 5.82% 6,514,471 (2,739,258) $ 1,341,192,275 $ 78,002,923 5.816% 5.82% $ 78,002,923 $ - Attachment A Base Equalization Rate Charge Increase $/kWh (%) 9. 10. 0.00063 0.60% 0.00263 1.88% 0.00108 0.95% 0.00010 0.10% (0.00069) -0.82% 0.00245 1.79% 0.00067 0.66% (0.00022) -0.24% (0.00103) -1.32% (0.00121) -1.64% (0.00163) -2.45% Page 1 of 1

 


Attachment B ARIZONA PUBLIC SERVICE COMPANY Palo Verde Decommissioning/ISFSI Trust Amounts Test Year 12 Months Ended 12/31/10 (Dollars in Thousands) ACC 6/1/2045 4/24/2046 11/25/2047 Jurisdictional YEAR UNITl UNIT2 UNIT3 TOTAL Amount(1) 2011 $ 4,558 $ 6,047 $ 5,414 $ 16,019 $ 15,630 2012 449 14,968 1,832 17,249 16,830 2013 449 14,968 1,832 17,249 16,830 2014 449 14,968 1,832 17,249 16,830 2015 449 14,968 1,832 17,249 16,830 2016 449 1,832 2,281 2,226 2017 449 1,832 2,281 2,226 2018 449 1,832 2,281 2,226 2019 449 1,832 2,281 2,226 2020 449 1,832 2,281 2,226 2021 449 1,832 2,281 2,226 2022 449 1,832 2,281 2,226 2023 449 1,832 2,281 2,226 2024 449 1,832 2,281 2,226 2025 449 1,832 2,281 2,226 2026 449 1,832 2,281 2,226 2027 449 1,832 2,281 2,226 2028 449 1,832 2,281 2,226 2029 449 1,832 2,281 2,226 2030 449 1,832 2,281 2,226 2031 449 1,832 2,281 2,226 2032 449 1,832 2,281 2,226 2033 449 1,832 2,281 2,226 2034 449 1,832 2,281 2,226 2035 449 1,832 2,281 2,226 2036 449 1,832 2,281 2,226 2037 449 1,832 2,281 2,226 2038 449 1,832 2,281 2,226 2039 449 1,832 2,281 2,226 2040 449 1,832 2,281 2,226 2041 449 1,832 2,281 2,226 2042 449 1,832 2,281 2,226 2043 449 1,832 2,281 2,226 2044 449 1,832 2,281 2,226 2045 225 1,832 2,056 2,006 2046 1,832 1,832 1,787 2047 1,832 1,832 1,787 $ 19,604 $ 65,919 $ 71,360 $ 156,883 $ 153,071 (1) ACC Jurisdictional share is approximately 97.57% Page 1 of 1 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 Table of Contents Power Supply Adjustment Plan of Administration Proposed Plan of Administration Power Supply Adjustor Mechanism 1. General Description 1 2. PSA Components 2 3. Calculation of the PSA Rate 4 4. Filing and Procedural Deadlines 5 5. Verification and Audit 6 6. Definitions 6 7. Schedules 8 8. Compliance Reports 9 9. Allowable Costs 10 1. General Description This document describes the plan for administering the Power Supply Adjustment mechanism ("PSA") approved for Arizona Public Service Company ("APS") by the Commission on June 28, 2007 in Decision No. 69663, amended by the Commission on December 30, 2009 in Decision No. 71448, and as further amended by the Commission on [insert date] in Decision No. xxxxx. The PSA provides for the recovery of fuel and purchased power costs, to the extent that actual fuel and purchased power costs deviate from the amount recovered through APS' Base Cost of Fuel and Purchased Power ($0.032071 per kWh) authorized in Decision No. XXXXX, from [insert date]. It also provides for refund or recovery of the net margins from sales of emission allowances, to the extent the actual sales margins deviate from the base rate amount of ($0.000001) per kWhl . The PSA described in this Plan of Administration ("POA") uses a forward-looking estimate of fuel and purchased power costs and margins on the sales of emission allowances ("PSA Costs") to set a rate that is then reconciled to actual costs experienced. This PSA includes a limit of $0.004 per kilowatt-hour (kWh) on the amount the PSA rate may change in any one year absent express approval of the Commission. This PSA also provides a mechanism for mid-year rate adjustment in the event that conditions change sufficiently to cause extraordinarily high balances to accrue under application of this PSA. 1 ($0.000001) per kWh is the result of the following: (2010 net gains from sales of S02 allowances of $21,178)/(2010 test year native load sales of 28,075,248 MWh)/1000. Effective Date XX/XX/XXXX Page 1 Attachment C Page 1 of 20

 


Arizona Corporation Commission Docket No. E-01345A-11-0224 2. PSA Components Proposed Plan of Administration Power Supply Adjustor Mechanism The PSA Rate will consist of three components designed to provide for the recovery of actual, prudently incurred PSA Costs. Those components are: 1. The Forward Component, which recovers or refunds differences between expected PSA Year (each February 1 through January 31 period shall constitute a PSA Year) PSA Costs and those embedded in base rates. 2. The Historical Component, which tracks the differences between the PSA Year's actual fuel and purchased power costs and those recovered through the combination of base rates and the Forward Component, and which provides for their recovery during the next PSA Year. 3. The Transition Component, which provides for: a. The opportunity to seek mid-year changes in the PSA rate in cases where variances between the anticipated recovery of fuel and purchased power costs for the PSA Year under the combination of base rates and the Forward Component become so large as to warrant recovery/refund, should the Commission deem such an adjustment to be appropriate. b. The tracking of balances resulting from the application of the Transition Components, in order to provide a basis for the refund or recovery of any such balances. Except for circumstances when the Commission approves new base rates, a PSA Year begins on February 1 and ends on the ensuing January 31. In the event that new base rates become effective on a date other than February 1, the Commission may, at its discretion, adjust any or all of the PSA components to reflect the new base rates. On or before September 30 of each year, APS will submit a PSA Rate filing, which shall include a calculation of the three components of the proposed PSA Rate. This filing shall be accompanied by such supporting information as Staff determines to be required. APS will supplement this filing with Historical Component and Transition Component filings on or before December 31 in order to replace estimated balances with actual balances, as explained below. a. Forward Component Description The Forward Component is intended to refund or recover the difference between: (1) PSA Costs embedded in base rates and (2) the forecast PSA Costs over a PSA Year that begins on February 1 and ends on the ensuing January 31. APS will submit, on or before September 30 of each year, a forecast for the upcoming calendar year (January I-December 31) of its PSA Costs. It will also submit a forecast of kWh sales for the same calendar year, and divide the forecast costs by the forecast sales to produce the cents/kWh unit rate required to collect those costs over those sales. The result of subtracting the Base PSA Costs from this unit rate shall be the Forward Component. APS shall maintain and report monthly the balances in a Forward Component Tracking Account, which will record APS' over/under-recovery of its actual PSA Costs as compared to the Base PSA Costs recovered in revenue. The balance calculated as a result of these steps is then reduced Effective Date XX/XX/XXXX Page 2 Attachment C Page 2 of 20

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism by the current month's collection of Forward Component revenue. This account will operate on a PSA Year basis (i.e.; February to January), and its balances will be used to administer this PSA's Historical Component, which is described immediately below. b. Historical Component Description The Historical Component in any current PSA Year is intended to refund or recover the balances accumulated in the Forward Component Tracking Account (described above) and Historical Component Tracking Account (described below) during the immediately preceding PSA Year. The sum of the projected Forward Component Tracking Account balance on January 31 of the following calendar year and the projected Historical Component Tracking Account balance on January 31 of the following calendar year is divided by the forecast kWh sales used to set the Forward Component for the coming PSA Year. That result comprises the proposed Historical Component for the coming PSA year. APS shall maintain and report monthly the balances in a Historical Component Tracking Account, which will reflect monthly collections under the Historical Component and the amounts approved for use in calculating the Historical Component. Each annual September 30 APS filing will include an accumulation of Forward Component Tracking Account balances and Historical Component Tracking Account balances for the preceding February through August and an estimate of the balances for September through January (the remaining five months of the current PSA Year). The APS filing shall use these balances to calculate a preliminary Historical Component for the coming PSA Year2. On or before December 31, APS will submit a supplemental filing that recalculates the preliminary Historical Component. This recalculation shall replace estimated monthly balances with those actual monthly balances that have become available since the September 30 filing. The September 30 filing's use of estimated balances for September through January (with supporting workpapers) is required to allow the PSA review process to begin in a way that will support its completion and a Commission decision, if necessary, prior to February 1. The December 31 updating will allow for the use of the most current balance information available prior to the time when a Commission decision, if necessary, is expected. In addition to the December 31 update filing, APS monthly filings (for the months of September through December) of Forward Component Tracking Account balance information and Historical Component Tracking Account balance information will include a recalculation (replacing estimated balances with actual balances as they become known) of the projected Historical Component unit rate required for the next PSA Year.3 The Historical Component Tracking Account will measure the changes each month in the Historical Component balance used to establish the current Historical Component as a result of collections under the Historical Component in effect. It will subtract each month's Historical 2 For example, the September 30, 2008 filing would include actual balances for February through August of 2008 and estimated balances for September 2008 through January 2009. 3 This updating to replace estimated with actual information will allow for the Commission to use the latest available balance information in determining what Historical Component is appropriate to establish for the coming PSA Year. Effective Date XX/XX/XXXX Page 3 Attachment C Page 3 of 20

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Component collections from the Historical Component balance. The Historical Component Account will also include Applicable Interest on any balances. APS shall file the amounts and supporting calculations and workpapers for this account each month. c. Transition Component Description The Transition Component will be used as the method for incorporating any future, approved mid-year changes to the PSA rate. APS or Staff may request at any timea change in the PSA rate through an adjustment to the Transition Component to address a significant imbalance between anticipated collections and costs for the PSA Year under the Forward Component element of this PSA. After the review of such request, the Commission may provide for the refund or collection of such balance (through a change to the Transition Component Balance) over such period as the Commission determines appropriate through a unit rate ($/kWh) imposed as part of the Transition Component. The Commission on its own motion may also change the PSA rate as described above. Notwithstanding the preceding paragraph, APS may at any time during the PSA Year request to reduce the PSA through the Transition Component, which request shall become effective beginning with the first billing cycle of the month following the filing of such a request, provided APS files the request within the first 15 days of a month and Staff does not file opposition to the request. A Transition Component Tracking Account will measure the changes each month in the Transition Component balance. APS, Staff, or the Commission on its own motion may request that the balance in any Transition Component Tracking Account at the end of the period set for recovery be included in the establishment of the Transition Component for the coming PSA Year. The Transition Component Account will also include Applicable Interest as determined by the Commission. APS shall file the amounts and supporting calculations and workpapers for this account each month. As it must do for the Historical Component filing, APS shall file on or before September 30 of each year an accumulation of Transition Component Tracking Account balances for the preceding February through August and an estimate of the balances for September through January (the remaining five months of the prior PSA Year). Those balances will form the basis for setting the preliminary Transition Component for the coming PSA Year. On or before December 31, APS will submit a supplemental filing to update the Transition Component calculation in the same manner as required for the Historical Component. 3. Calculation of the PSA Rate The PSA rate is the sum of the three components; i.e., Forward Component, Historical Component, and Transition Component. The PSA rate shall be applied to customer bills. Unless the Commission has otherwise acted on a new PSA rate by February 1, the proposed PSA rate (as amended by the updated December 31 filing) shall go into effect. However, the PSA rate may Effective Date XX/XX/XXXX Page 4 Attachment C Page 4 of 20

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism not change from the prior year's PSA rate by more than plus or minus $0.004 per kWh without an offsetting change in the Base Cost of Fuel and Purchased Power. The PSA rate shall be applicable to APS' retail electric rate schedules (with the exception of E-36 XL, AG-l, Direct Access service and any other rate that is exempt from the PSA) and is adjusted annually. The PSA Rate shall be applied to the customer's bill as a monthly kWh charge that is the same for all customer classes. The PSA rate shall be reset on February 1 of each year, and shall be effective with the first February billing cycle unless suspended by the Commission. It is not prorated. 4. Filing and Procedural Deadlines a. September 30 Filing APS shall file the PSA rate with all Component calculations for the PSA year beginning on the next February 1, including all supporting data, with the Commission on or before September 30 of each year. That calculation shall use a forecast of kWh sales and ofPSA Costs for the coming calendar year, with all inputs and assumptions being the most current available for the Forward Component. The filing will also include the Historical Component calculation for the year beginning on the next February 1, with all supporting data. That calculation shall use the same forecast of sales used for the Forward Component calculation. The Transition Component filing shall also include a proposed method for addressing the over or under recovery of any Transition Component balances that result from changes in the sales forecasts or recovery periods set or any additions to or subtractions from Transition Component balances reviewed or approved by the Commission since the last February 1 resetting ofthe new PSA.4 b. December 31 Filing APS shall by December 31 update the September 30 filing. This update shall replace estimated Forward Component Tracking Account balances, the Historical Component Tracking Account balances, and the Transition Component Tracking Account balances with actual balances and with more current estimates for those months (December and January) for which actual data are not available. Unless the Commission has otherwise acted on the APS calculation by February 1, the PSA rate proposed by APS shall go into effect with the first February billing cycle.5 c. Additional Filings APS shall also file with the Commission any additional information that the Staff determines it requires to verify the component calculations, account balances, and any other matter pertinent to the PSA. 4 This method assumes that the Commission defers the recovery of any approved Transition Component Balance changes until the next February 1 PSA resetting. The Commission may also, as part of the approval of any such Transition Component Balance change, make a PSA change effective on dates and across periods as it determines to be appropriate when it approves such a Transition Component Balance change. 5 No reference in this plan to effectiveness in the absence of Commission action shall be interpreted as precluding the normal application ofthe balance reconciliation provisions generally established for the PSA. Effective Date XX/XX/XXXX Page 5 Attachment C Page 5 of 20

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 d. Review Process Proposed Plan of Administration Power Supply Adjustor Mechanism The Commission Staff and interested parties shall have an opportunity to review the September 30 and December 31 forecast, balances, and supporting data on which the calculations of the three PSA components have been based. Any objections to the September 30 calculations shall be filed within 45 days of the APS filing. Any objections to the December 31 calculations shall be filed within 15 days of the APS filing. 5. Verification and Audit The amounts charged through the PSA shall be subject to periodic audit to assure their completeness and accuracy and to assure that all fuel and purchased power costs were incurred reasonably and prudently. The Commission may, after notice and opportunity for hearing, make such adjustments to existing balances or to already recovered amounts as it finds necessary to correct any accounting or calculation errors or to address any costs found to be unreasonable or imprudent. Such adjustments, with appropriate interest, shall be recovered or refunded through the Transition Component. 6. Definitions Applicable Interest - Interest is applied on the PSA balance annually at the following rates: any over-collection existing at the end of the PSA year will be credited an amount equal to interest at a rate equal to the Company's authorized Return on Equity ("ROE") or APS's then-existing short term borrowing rate, whichever is greater, and will be refunded to customers over the following 12 months; any under-collection existing at the end of the PSA Year will be debited an amount equal to interest at a rate equal to the Company's authorized ROE or APS'S then-existing short term borrowing rate, whichever is less, and will be recovered from customers over the following 12 months. Base Cost of Fuel and Purchased Power - An amount generally expressed as a rate per kWh, which reflects the fuel and purchased power cost embedded in the base rates as approved by the Commission in APS's most recent rate case. The Base Cost of Fuel and Purchased Power recovered in base revenue is the approved rate per kWh times the applicable sales volumes. Decision No. xxxxx set the base cost at $0.0.032071 per kWh effective on [insert date]. Base Net Margins on the Sale of Emission Allowances - An amount generally expressed as a rate per kWh, which reflects the net margins on sales of S02 emission allowances embedded in the base rates as approved by the Commission in APS' s most recent rate case. The Base Net Margins on the Sale of Emission Allowances is set at ($0.000001) per kWh effective on [insert date]. Base PSA Costs - A rate equal to the sum of Base Cost of Fuel and Purchased Power and the Base Net Margins on the Sale of Emission Allowances. Forward Component - An amount generally expressed as a rate per kWh charge that is updated annually on February 1 of each year and effective with the first billing cycle in February. The Forward Component for the PSA Year will adjust for the difference between the forecast PSA Effective Date XX/XX/XXXX Page 6 Attachment C Page 6 of 20

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Costs generally expressed as a rate per kWh less the Base PSA Costs generally expressed as a rate per kWh embedded in APS's base rates. The result of this calculation will equal the Forward Component, generally expressed as a rate per kWh. Forward Component Tracking Account - An account that records on a monthly basis APS's over/under-recovery of its actual PSA Costs as compared to the actual Base PSA Costs recovered in revenue and Forward Component revenue, plus Applicable Interest. The balance of this account as of the end of each PSA Year is, subject to periodic audit, reflected in the next Historical Component calculation. APS files the balances and supporting details underlying this Account with the Commission on a monthly basis. Historical Component - An amount generally expressed as a rate per kWh charge that is updated annually on February 1 of each year and effective with the first billing cycle in February unless suspended by the Commission. The purpose of this charge is to provide for a true-up mechanism to reconcile any over or under-recovered amounts from the preceding PSA Year tracking account balances to be refunded/collected from customers in the coming year's PSA rate. Historical Component Tracking Account - An account that records on a monthly basis the account balance to be collected via the Historical Component rate as compared to the actual Historical Component revenues; plus Applicable Interest; The balance of which at the close of the preceding PSA Year is, subject to periodic audit, then reflected in the next Historical Component calculation. APS files the balances and supporting details underlying this Account with the Commission on a monthly basis. ISFSI - Costs associated with the Independent Spent Fuel Storage Installation that stores spent nuclear fuel. Mark-to-Market Accounting - Recording the value of qualifying commodity contracts to reflect their current market value relative to their actual cost. Native Load - Native load includes customer load in the APS control area for which APS has a generation service obligation and PacifiCorp Supplemental Sales. Net Margins on the Sale of Emission Allowances - Revenues incurred from the sale of emission allowances net of the costs incurred to produce the excess allowances. PacifiCorp Supplemental Sales - The PacifiCorp Supplemental Sales agreement is a long-term contract from 1990 which requires APS to offer a certain amount of energy to PacifiCorp each year. It is a component of the set of agreements that led to the sale of Cholla Unit 4 to PacifiCorp and the establishment of the seasonal diversity exchange with PacifiCorp. Preference Power - Power allocated to APS wholesale customers by federal power agencies such as the Western Area Power Administration. PSA - The Power Supply Adjustment mechanism approved by the Commission in Decision No. 69663, amended by the Commission in Decision No. 71448, and further amended by the Effective Date XX/XX/XXXX Page 7 Attachment C Page 7 of 20

 


Arizona Corporation Commission Docket No. E-01345A-ll-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Commission in Decision No. xxxxx, which is a combination of three rate components that track changes in the cost of obtaining power supplies based upon forward-looking estimates of PSA Costs that are eventually reconciled to actual costs experienced. This PSA allows for special Commission consideration of extreme volatility in costs or recovery by means of a mid-year rate correction, and provides for a reconciliation between actual and estimated costs of the last two months of estimated costs used in Historical Component calculations. PSA Costs - The combination of System Book Fuel and Purchased Power Costs net of the System Book Off-System Sales Revenues as adjusted herein for Rate Schedule AG-l plus the Net Margins on the Sales of Emission Allowances. PSA Year - A consecutive 12-month period generally beginning each February 1. Rate Schedule AG-l - Experimental Alternative Generation Rate Schedule approved by the Commission in Decision No. XXXXX. Resale of capacity and energy displaced by Rate Schedule AG-l shall be excluded from the PSA on a pro-rata basis, by dividing the amount of monthly metered sales to AG-l customers by the net monthly total of off-system sales and multiplying that result by total off-system sales margins. The portion of capacity and energy sales margins that is not the result of displacement from Rate Schedule AG-l will continue to be a credit to the PSA. System Book Fuel and Purchased Power Costs - The costs recorded for the fuel and purchased power used by APS to serve both Native Load and off-system sales, less the costs associated with applicable special contracts, E-36 XL, AG-l, RCDAC-l, ISFSI, and Mark-to-Market Accounting adjustments. Wheeling costs are included; broker fees are included up to the level in the Base Cost of Fuel and Purchased Power authorized in Decision No.xxxxx. System Book Off-System Sales Revenue - The revenue recorded from sales made to non-Native Load customers, for the purpose of optimizing the APS system, using APS-owned or contracted generation and purchased power, less Mark-to-Market Accounting adjustments. Traditional Sales-for-Resale - The portion of load from Native Load wholesale customers that is served by APS, excluding the load served with Preference Power. Transition Component - An amount generally expressed as a rate per kWh charge to be applied when necessary to provide for significant changes between estimated and actual costs under the Forward Component. Transition Component Tracking Account - An account that records on a monthly basis the account balance to be collected via the Transition Component as compared to the actual Transition Component revenues, plus applicable interest; the balance of which upon Commission consideration may then be reflected in the next Transition Component calculation. APS files the balances and supporting details underlying this Account with the Commission on a monthly basis. Effective Date XX/XX/XXXX Page 8 Attachment C Page 8 of 20

 

 


Arizona Corporation Commission Docket No. E-01345A-11-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism Wheeling Costs (FERC Account 565, Transmission of Electricity by Others) - Amounts payable to others for the transmission of APS’s electricity over transmission facilities owned by others. 7. Schedules Samples of the following schedules are attached to this Plan of Administration Schedule 1 Schedule 2 Schedule 3 Schedule 4 Schedule 5 Schedule 6 Schedule 7 Power Supply Adjustment (PSA) Rate Calculation PSA Forward Component Rate Calculation PSA Year Forward Component Tracking Account PSA Historical Component Rate Calculation Historical Component Tracking Account PSA Transition Component Rate Calculation PSA Transition Tracking Account 8. Compliance Reports APS shall provide monthly reports to Staffs Compliance Section and to the Residential Utility Consumer Office detailing all calculations related to the PSA. An APS Principal Officer, as listed in the Company's annual report filed with the Commission's Corporations Division, shall certify under oath that all information provided in the reports itemized below is true and accurate to the best of his or her information and belief. These monthly reports shall be due within 30 days of the end of the reporting period. The publicly available reports will include at a minimum: 1. The PSA Rate Calculation (Schedule 1); Forward Component, Historical Component, and Transition Component Calculations (Schedules 2, 4, and 6); Annual Forward Component, Historical Component, and Transition Component Tracking Account Balances (Schedules 3, 5, and 7). Additional information will provide other relative inputs and outputs such as: a. Total power and fuel costs. b. Margins on the sale of excess emission allowances. c. Off-system sales margins attributable to capacity freed up due to Rate Schedule AG-l. d. Customer sales in both MWh and thousands of dollars by customer class. e. Number of customers by customer class. f. A detailed listing of all items excluded from the PSA calculations. g. A detailed listing of any adjustments to the adjustor reports. h. Total off-system sales revenues. i. System losses in MW and MWh. j. Monthly maximum retail demand in MW. 2. Identification of a contact person and phone number from APS for questions. Effective Date XX/XX/XXXX Page 9 Attachment C Page 9 of 20

 


Arizona Corporation Commission Docket No. E-01345A-11-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism APS shall provide to Commission Staff monthly reports containing the information listed below. These reports shall be due within 30 days of the end of the reporting period. All of these additional reports will be provided confidentially. A. Information for each generating unit shall include the following items: 1. Net generation, in MWh per month, and 12 months cumulatively. 2. Average heat rate, both monthly and 12-month average. 3. Equivalent forced-outage rate, both monthly and 12-month average. 4. Outage information for each month including, but not limited to, event type, start date and time, end date and time, and a description. 5. Total fuel costs per month. 6. The fuel cost per kWh per month. B. Information on power purchases shall include the following items per seller (information on economy interchange purchases may be aggregated): 1. The quantity purchased in MWh. 2. The demand purchased in MW to the extent specified in the contract. 3. The total cost for demand to the extent specified in the contract. 4. The total cost of energy. C. Information on off-system sales shall include the following items: 1. An itemization of off-system sales margins per buyer. 2. Details on negative off-system sales margins. D. Fuel purchase information shall include the following items: 1. Natural gas interstate pipeline costs, itemized by pipeline and by individual cost components, such as reservation charge, usage, surcharges and fuel. 2. Natural gas commodity costs, categorized by short-term purchases (one month or less) and longer term purchases, including price per therm, total cost, supply basin, and volume by contract. E. APS will also provide: 1. Monthly projections for the next 12-month period showing estimated (Over)/under-collected amounts. 2. A summary of unplanned outage costs by resource type. 3. A summary of the net margins on the sale of emission allowances. 4. The data necessary to arrive at the System and Off-System Book Fuel and Purchased Power cost reflected in the non-confidential filing. 5. The data necessary to arrive at the Native Load Energy Sales MWh reflected in the non-confidential filing. Work papers and other documents that contain proprietary or confidential information will be provided to the Commission Staff under an appropriate confidentiality agreement. APS will keep fuel and purchased power invoices and contracts available for Commission review. The Commission has the right to review the prudence of fuel and power purchases and any Effective Date XX/XX/XXXX Page 10 Attachment C Page 10 of 20

 


Arizona Corporation Commission Docket No. E-01345A-11-0224 Proposed Plan of Administration Power Supply Adjustor Mechanism calculations associated with the PSA at any time. Any costs flowed through the PSA are subject to refund if those costs are found to be imprudently incurred. 9. Allowable Costs a. Accounts The allowable PSA costs include fuel and purchased power costs incurred to provide service to retail customers. And, the prudent direct costs of contracts used for hedging system fuel and purchased power will be recovered under the PSA. Additionally, the net margins on the sale of emission allowances will also be refunded or recovered through the PSA. The allowable cost components include the following Federal Energy Regulatory Commission (“FERC”) accounts: • 501 Fuel (Steam) • 518 Fuel (Nuclear) less ISFSI regulatory amortization • 547 Fuel (Other Production) • 555 Purchased Power • 565 Wheeling (Transmission of Electricity by Others) • 411 O&M (Margins on the Sale of Emission Allowances) Additionally, broker fees recorded in FERC account 557 are allowable up to the limit set in Decision  No. xxxxx. These accounts are subject to change if the Federal Energy Regulatory Commission alters its accounting requirements or definitions. b. Directly Assignable Power Supply Costs Excluded Decision No. 66567 provides APS the ability to recover reasonable and prudent costs associated with customers who have left APS standard offer service, including special contract rates, for a competitive generation supplier and then return to standard offer service. For administrative purposes, customers who were direct access customers since origination of service and request standard offer service would be considered to be returning customers. A direct assignment or special adjustment may be applied that recognizes the cost differential between the power purchases needed to accommodate the returning customer and the power supply cost component of the otherwise applicable standard offer service rate. This process is described in the Returning Customer Direct Access Charge rate schedule and associated Plan for Administration filed with the Commission. In addition, if APS purchases power under specific terms on behalf of a standard offer special contract customer, the costs of that power may be directly assigned. In both cases, where specific power supply costs are identified and directly assigned to a large returning customer or standard offer special contract customer or group of customers, these costs will be excluded from the Adjustor Rate calculations. Schedule E-36 XL, and AG-l customers are directly assigned power supply costs based on the APS system incremental cost at the time the customer is consuming power from the APS system so their power supply costs and kWh usage are excluded from the PSA. Effective Date XX/XX/XXXX Page 11 Attachment C Page 11 of 20

 


ARIZONA PUBLIC SERVICE COMPANY Schedule 1 Power Supply Adjustment (PSA) Rate Calculation ($/kWh) Attachment C Page 12 of 20 Line Current Proposed Increase/(Decrease) No. PSA Rate Calculation February 1, XXXX February 1, XXXX 1 1 Forward Component Rate - FC (Schedule 2, L13) $- $- 2 Historical Component Rate - HC (Schedule 4, L5) 2 #.###### $- 3 PSA Transition Component Rate (Schedule 6, L3) 3 $- $- 4 PSA Rate (L1+ L2 + L3) #.###### $- Notes: 1 Proposed levels of the PSA rate components are provided in the September 30 filing and updated in the December 31 filing of each year. 2 A Historical Component is a true up related to respective prior period PSA activity. 3 Provides for Mid-Period Corrections when necessary. $/kWh % N/A N/A N/A N/A N/A N/A N/A N/A Page 1 of 9

 


ARIZONA PUBLIC SERVICE COMPANY Schedule 2 PSA Forward Component Rate Calculation ($ in thousands; Forward Component Rate in $/kWh) Line No. PSA Forward Component Rate - Calculation 1 Projected Fuel and Purchased Power Costs 2 Projected Off-System Sales Revenue 3 PSA Adjustments to Fuel and Purchased Power Costs 2 4 Net Fuel and Purchased Power Cost (L1 through L3) 5 Projected Net Margins on the Sale of Emission Allowances 6 Projected Billed Native Load Sales, excluding E-36XL, AG-1 (MWhs) 3 7 Projected Average Net Fuel Cost $/kWh (L4/ L6) 8 Projected Average Margin on Emission Allowances $/kWh (L5/ L6) 9 Total Projected Average PSA Cost $/kWh (L7+L8) 10 Authorized Base Cost of Fuel and Purchased Power Rate $/kWh 4 11 Authorized Base Net Margins on the Sale of Emission Allowances Rate $/kWh 12 Total Authorized Base Cost $/kWh 13 Forward Component Rate $/kWh (L9 - L12) Notes: $ $ $ $ Current February 15 XXXX $ #,###,### $ #,###,### $ (#,###,###) $ #,###,###- ##,###,### #.###### #.###### 0.032071 (0.000001) 0.032070 #.###### 1 Proposed levels are provided in the September 30 filing and updated in the December 31 filing of each year. Proposed February 15 XXXX 1 $ $ $ $ $ $ $ $ $ Attachment C Page 13 of 20 Increase/(Decrease) $ Values % N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A 2 Includes costs associated with E-36XL, AG-1 and other direct assignment customers, ISFSI, and mark-to-market accounting adjustments. 3 The Projected Billed Native Load Sales of X,XXX,XXX MWhs for the Current Rate represent forecast sales for XXXX as of December 30th, XXXX. They exclude ED 3 and City of Williams wholesale contracts that are excluded from the Proposed sales and fuel costs. 4 Base Cost of Fuel and Purchased Power established in Decision No . Schedule presentation will appear to round up to $000s and MWh; however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh. Page 2 of 9 $- - - $- - - $- $- $- $- $- $- $-

 


 

Attachment C

Page 14 of 20

 

ARIZONA PUBLIC SERVICE COMPANY

Schedule 3

XXXX PSA Year Forward Component Tracking Account - in Effect from February 1, XXXX to Jan 31, XXXX

($ in thousands; Forward Component Rate and Base Rate in $/kWh)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Feb-XX

 

Mar-XX

 

Apr-XX

 

May-XX

 

Jun-XX

 

Jul-XX

 

Aug-XX

 

Sept-XX

 

Oct-XX

 

Nov-XX

 

Dec-XX

 

Jan-XX

 

XXXX Total

 

1          Prior Month’s Balance

 

From L26

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Energy Sales

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2          PSA Retail Energy Sales(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3          Wholesale Native Load Energy Sales (2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4          Total Native Load Energy Sales

 

L2 + L3

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

 

 

5          Retail Energy Sales as a % of Total

 

L2 / L4

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6          Retail Billed Sales Excluding E-36XL, AG-1 Sales (MWh)(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7          Metered Sales to AG-1 Customers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8          Total Off-System Energy Sales

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9          Ratio of AG-1 sales to Total Off-System Sales

 

L7 / L8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PSA Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10   Fuel and Purchased Power Costs (4),(5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11   Off System Revenue (Credit)(6)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12   Off System Margin Displaced by AG-1 (Debit)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13   Net Margins on Sale of Emission Allowances

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

14   Net PSA Costs

 

sum(L10 to L13)

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retail PSA Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

15   Fuel and Purchased Power Costs

 

L5 * L10

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

16   Off System Revenue (Credit)

 

L5 * L11

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17   Off System Margin Displaced by AG-1 (Debit)

 

L5 * L12

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

18   Net Margins on Sale of Emission Allowances

 

L5 * L13

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

19   Net Retail PSA Costs

 

sum(L15 to L18)

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Base Rate Power Supply Recovery

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

20   Fuel and Purchased Power Recovery

 

L28 * L2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

21   Net Margins on Sale of Emission Allowances

 

L29 * L2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Over) Under Recovery From Base Rate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

22   Fuel and Purchased Power (Over) Under Recovery

 

(L15 + L16 + L17) - L20

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

23   Net Margins on Sale of Emission Allowances (Over) Under Recovery

 

L18 - L2I

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

24   Total (Over) Under Recovery

 

sum(L22 to L23)

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

25   Forward Component Collections(7)

 

-L30 * L6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

26   Tracking Account Balance

 

L1 + L24 - L25

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

 

 

27   Annual Interest (Calculated only in January)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

28   Total Base Fuel Rate - ¢ per kWh

 

 

 

3.2071

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

29   Base Net Margin on the Sale of Emission Allowances - ¢ per kWh

 

 

 

(0.0001

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

30   Forward Component Rate - ¢ per kWh

 

 

 

#.####

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Notes:

 

(1)         PSA Retail Energy Sales are the calendar month’s MWh sales. XXXX PSA Year Cumulative Retail Energy Sales of XX,XXX MWhs under rate schedule E-36XL, AG-1 were excluded from the PSA Calculations.

(2)         Includes traditional sales for resale. PacifiCorp supplemental sales, and other non-ACC jurisdictional sales. ED 3 and City of Williams energy sales are excluded from the PSA Calculation.

(3)         Retail Billed Sales on Line 6 relate specifically to the Forward Component Collections. Due to billing adjustments and timing, this amount will differ from other components’ Retail Billed Sales.

(4)         Renewables costs exclude $X,XXX,XXX of XXXX PSA Year year-to-date costs that are currently being recovered through the RES rate schedule.

(5)         Includes native load and off-system fuel and purchased power costs less those costs associated with E-36XL, AG-1 and other direct assignment customers, amortization of previously deferred ISFSI, Four Comers Coal Reclamation, and mark-to-market accounting adjustments.

(6)         Includes off-system revenue less mark-to-market accounting adjustments.

(7)         Generally, Line 30 * Line 6 = Line 25; however, differences may occur due to billing adjustments.

 

Schedule presentation will appear to round up to $000s: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh

 

Page 3 of 9


 


 

ARIZONA PUBLIC SERVICE COMPANY Schedule 4 PSA Historical Component Rate Calculation ($ in thousands; Historical Component Rate in $/kWh) Line No. PSA Historical Component Rate Calculation 1 Forward Component Tracking Account Balance (Schedule 3, L26 + L27) 2 Historical Component Tracking Account Balance (Schedule 5, L9 + L10) 2 3 Total Historical Amount to be (Refunded)/Collected Balance (L1+L2) 4 Projected Billed Retail Energy Sales without E-36 XL, AG-1 (MWh) 5 Applicable Historical Component Rate (L3/ L4) Notes: Current February 1, XXXX #,### #,### #,### ##,###,### #.###### 1 Proposed levels are provided in the September 30 filing and updated in the December 31 filing of each year. 2 The Current Rate Projected Billed Retail Energy Sales are for February XXXX through January XXXX. Proposed February 1, XXXX 1 $ $ $ Attachment C Page 15 of 20 Increase/(Decrease) $ Values % N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A Schedule presentation will appear to round up to $000s; however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh. Page 4 of 9

 


 

Attachment C

Page 16 of 20

 

ARIZONA PUBLIC SERVICE COMPANY

Schedule 5

Historical Component Tracking Account in Effect Feb 1, XXXX through Jan. 31, XXXX

($ in thousands Historical Component Rate in $/kWh)

 

Line

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

XXXX Data

 

 

 

 

 

 

 

 

 

 

 

XXXX

 

No.

 

 

 

January

 

February

 

March

 

April

 

May

 

June

 

July

 

August

 

September

 

October

 

November

 

December

 

January

 

1

 

Projected HC Tracking Account Balance at Dec. 31, XXXX

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2

 

Projected FC Tracking Account Balance at Dec. 31, XXXX

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3

 

True-up from December - January Estimate(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4

 

Prior Month’s Ending Balance

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5

 

HC Adjusted Beginning Balance (L1+ L2 + L3 + L4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6

 

Applicable Historical Component Rate ($/kWh)(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7

 

Retail Billed Sales Excluding E-36XL, AG-1 Sales (MWhs)(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8

 

Less Revenue from Applicable HC (L6 x L7)(4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9

 

HC Ending Balance (L5 - L8)

 

$

—

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10

 

Annual Interest (Calculated only in January)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Notes:

(1) True-up is the result of using estimated revenue and deferral for December and January since the actual amount was not available at the time of prior period PSA filing.

(2) Historical Component, Schedule 4, Line 5

(3) Sales amounts are for energy billed each period.

(4) Generally, Line 7 x Line 6 = Line 8; however, differences may occur due to billing adjustments.

 

Schedule presentation will appear to round up to $000s and MWh: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh.

 

Page 5 of 9



 

Line No. ARIZONA PUBLIC SERVICE COMPANY Schedule 6 PSA Transition Component Rate Calculation ($ in thousands; Transition Component Rate(s) in $/kWh) Current February 1, XXXX 1 1 PSA Transition - Approved (Refundable)/Collection Amount 1 N/A 2 Projected Energy Sales without E-36XL, AG-1 (MWh) XXX. X, XX to XXX. X,XX N/A 3 PSA Transition Component (Refundable)/Collection Rate (L1 / L2) N/A Notes: 1 Commission Decision No. XXXXXXXXXX Proposed February 1, XXXX 1 N/A N/A N/A Attachment C Page 17 of 20 Increase/(Decrease) $ Values % N/A 0.00% N/A 0.00% N/A 0.00% Schedule presentation will appear to round up to $000s and MWh; however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh. Page 6 of 9

 


 

Attachment C

Page 18 of 20

 

ARIZONA PUBLIC SERVICE COMPANY

Schedule 7

PSA Transition Tracking Account in Effect XX 1, 20XX through XX 31, 20XX

($ in thousands; Transition Component Rate in $/kWh)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Line

 

 

 

20XX Data

 

20XX

 

No.

 

 

 

January

 

February

 

March

 

April

 

May

 

June

 

July

 

August

 

September

 

October

 

November

 

December

 

January

 

1

 

Transferred balance from FC Tracking Acct Per Decision No. XXXXX

 

 

 

 

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

2

 

Prior Month’s Ending Balance

 

 

 

 

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

3

 

Transition Component TA Adjusted Beginning Balance (L1+ L2)

 

 

 

 

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

4

 

Applicable Transition TA Component Rate ($/kWh) (1)

 

 

 

 

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

5

 

Retail Billed Sales Excluding E-36XL, AG-1 Sales (MWhs) (2)

 

 

 

 

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

—

 

6

 

Less Revenue from Applicable Transition Component (L4 x L5)(3)

 

 

 

 

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

7

 

Ending Balance; (L3 - L6)

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

$

—

 

 


Notes:

(1) Transition Component, Schedule 6, Line 3

(2) Sales amounts are for energy billed each period.

(3) Generally, Line 4 x Line 5 = Line 6; however, differences may occur due to billing adjustments.

 

Schedule presentation will appear to round up to $000s and MWh: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh.

 

Page 7 of 9



 

Attachment C

Page 19 of 20

 

ARIZONA PUBLIC SERVICE COMPANY

Schedule 8

Summary of Monthly Calculations

Mo YYYY

($ in thousands)

 

Line

 

 

 

XXXX Data

 

XXXX

 

No.

 

 

 

January

 

February

 

March

 

April

 

May

 

June

 

July

 

August

 

September

 

October

 

November

 

December

 

January

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

XXXX Forward Component Tracking Account

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1

 

Beginning Balance

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2

 

Transfers to XXXX Historical Component Tracking Account

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

3

 

Post-Sharing (Over)/Under Collection

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4

 

Less Revenue from Applicable Forward Component Rate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

5

 

Annual Interest (Calculated only in January)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6

 

Ending Balance (Line 1 + Line 2 + Line 3 - Line 4 + Line 5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

XXXX Historical Component Tracking Account

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7

 

Beginning Balance

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8

 

Transfers from XXXX Forward Component Tracking Account

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9

 

Less Revenue from Applicable Historical Component Rate

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

10

 

Annual Interest (Calculated only in January)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

11

 

Ending Balance (Line 7 + Line 8 - Line 9 + Line 10)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12

 

Combined Balance ([Line 6 + Line 11])(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

13

 

Annual Interest Rate

 

#.##

%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Schedule presentation will appear to round up to $000s and MWh: however, calculations are performed on an actual $ and kWh basis with resultant Rates/kWh rounded up to $0.000000/kWh.

 

Page 8 of 9



 

Attachment C

Page 20 of 20

 

ARIZONA PUBLIC SERVICE COMPANY

Schedule 9

YYYY Native Load Customer Counts, Sales and Revenue

Mo YYYY

 

Line

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

No.

 

Class

 

January

 

February

 

March

 

April

 

May

 

June

 

July

 

August

 

September

 

October

 

November

 

December

 

Total(1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Customers

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1

 

Residential

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

#DIV/0!

 

2

 

Commercial

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

#DIV/0!

 

3

 

Industrial